Systems and methods for processing heavy oils

ABSTRACT

According to one embodiment, a heavy oil may be processed by a method that may include upgrading at least a portion of the heavy oil to form an upgraded oil, where the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil. The final boiling point of the upgraded oil may be less than or equal to 540° C. The second hydrocracking catalyst cracks at least a portion of vacuum gas oil in the heavy oil. The first hydrocracking catalyst may comprise a greater average pore size than the second hydrocracking catalyst.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 62/533,416 filed Jul. 17, 2017, the entire contents of which are incorporated by reference.

BACKGROUND Field

The present disclosure relates to processes and apparatuses for the processing of petroleum based feeds. More specifically, embodiments of the present disclosure relate to the processing of heavy oils, including crude oils, to form chemical products and intermediaries.

Technical Background

Petrochemical feeds, such as crude oils, can be converted to chemical intermediates such as ethylene, propylene, butenes, butadiene, and aromatic compounds such as benzene, toluene, and xylene, which are basic intermediates for a large portion of the petrochemical industry. They are mainly obtained through the thermal cracking (sometimes referred to as “steam pyrolysis” or “steam cracking”) of petroleum gases and distillates such as naphtha, kerosene, or even gas oil. Additionally, petrochemical feeds may be converted to transportation fuels such a gasoline, diesel, et cetera. However, as demands rise for these basic intermediate compounds and fuels, other production methods must be considered beyond traditional refining operations.

BRIEF SUMMARY

There is a need for processes that produce chemical intermediates, such as ethylene, propylene, butenes, butadiene, and aromatic compounds such as benzene, toluene, and xylene from heavy oil feeds, such as crude oil. In one or more embodiments, catalytic treatment processes (sometimes referred to herein as pretreating, hydroprocessing, or hydrotreating) and catalysts for use in such processes are disclosed. In one or more embodiments, the catalyst for use in such processes have enhanced catalytic functionality and, in particular, have enhanced aromatic cracking functionality, and through such catalytic treatment processes, heavy oils may be upgraded and converted to at least chemical intermediates by subsequent processing, such as steam cracking. The steam cracking may be performed without any intermediate steps which reduce the final boiling point of the upgraded oil. In other embodiments, the upgraded oil can be directly separated in to transportation fuels.

The presently-described catalytic treatment processes (for example, the upgrading), according to one or more embodiments, may have enhanced catalytic functionality with regards to reducing at least aromatic content, metal content, and nitrogen content in a crude oil feedstock, which may be subsequently refined into desired petrochemical products by a number of different processes disclosed herein. According to one or more embodiments, heavy oils may be treated by five catalysts arranged in series, where the primary function of the first catalyst (that is, the hydrodemetalization catalyst) is to remove metals from the heavy oil; the primary function of the second catalyst (that is, the transition catalyst) is to remove metals, sulfur, and nitrogen from the heavy oil and to provide a transition area between the first and third catalysts; the primary function of the third catalyst (that is, the hydrodenitrogenation catalyst) is to further remove nitrogen, sulfur, or both, and saturate the aromatics from the heavy oil; the primary function of the fourth catalyst (that is, the first hydrocracking catalyst) is to reduce aromatic content in the heavy oil; and the primary function of the fifth catalyst (that is, the second hydrocracking catalyst) is to further reduce aromatic content in the heavy oil (particularly of vacuum gas oil constituents of the heavy oil). The overall pretreatment process may result in one or more of an increased concentration of paraffins, a decreased concentration of polynuclear aromatic hydrocarbons, and a reduced final boiling point of the pretreated oil with respect to the heavy oil feedstock.

Without being bound by theory, it is believed that the first hydrocracking catalyst and the second hydrocracking catalyst may together serve to crack the oil components of the heavy oil stream to produce an upgraded oil. The second hydrocracking catalyst may target cracking of vacuum gas oil components in the feed oil. Without being bound by theory, it is also believed that the relatively large-sized pores (that is, mesoporosity) of the presently-described first hydrocracking catalysts of one or more embodiments may allow for larger molecules of crude oil to diffuse inside the support, which are believed to enhance the reaction activity and selectivity of the catalyst. Compared to the first hydrocracking catalyst described herein, the second hydrocracking catalyst may have one or more of a smaller average pore size, a lesser pore volume, a greater surface area, or greater acidity, which may make the second hydrocracking catalyst better suited to promote reactions that further crack the molecules of vacuum gas oils. Due at least to the presence of additional microporous sites as compared with some embodiments of the first hydrocracking catalyst, molecules of vacuum gas oils may be efficiently cracked by the second hydrocracking catalyst. Additionally, the upgraded oil converted by the second hydrocracking catalysts may be may be better suited for downstream processing, for example, steam cracking.

According to one embodiment, a heavy oil may be processed by a method that may include upgrading at least a portion of the heavy oil to form an upgraded oil, where the upgrading may comprise contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil. The final boiling point of the upgraded oil may be less than or equal to 540° C., and the first hydrocracking catalyst may comprise a greater average pore size than the second hydrocracking catalyst.

According to another embodiment, a heavy oil may be processed by a method that may include upgrading at least a portion of the heavy oil to form an upgraded oil, where the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil. The method may further comprise passing the upgraded oil to a steam cracker and steam cracking the upgraded oil to form a steam-cracked effluent stream. At least the heaviest components of the upgraded oil may be passed to the steam cracker, and the first hydrocracking catalyst may comprise a greater average pore size than the second hydrocracking catalyst.

Additional features and advantages of the technology described in this disclosure will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from the description or recognized by practicing the technology as described in this disclosure, including the detailed description which follows, the claims, as well as the appended drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings, where like structure is indicated with like reference numerals and in which:

FIG. 1 depicts a generalized diagram of a chemical pretreatment system, according to one or more embodiments described in this disclosure;

FIG. 2 depicts a generalized diagram of a chemical pretreatment system which includes a hydrodemetalization (HDM) catalyst, a transition catalyst, a hydrodenitrogenation (HDN) catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst, according to one or more embodiments described in this disclosure;

FIG. 3 depicts a generalized diagram of a chemical pretreatment system which includes a hydrodemetalization (HDM) catalyst, a transition catalyst, and a hydrodenitrogenation (HDN) catalyst and a downstream packed bed pretreatment reactor comprising a first hydrocracking catalyst and a second hydrocracking catalyst, according to one or more embodiments described in this disclosure;

FIG. 4 depicts a generalized diagram of a chemical processing system utilized subsequent to the chemical pretreatment system where the upgraded heavy oil is introduced to a fractionator with some of the resulting streams sent to a hydrocracker, according to one or more embodiments described in this disclosure;

FIG. 5 depicts a generalized diagram of another chemical processing system utilized subsequent to the chemical pretreatment system where the upgraded heavy oil is introduced to a refinery fractionator with some of the resulting streams sent to a fluid catalytic cracking (FCC) conversion unit, according to one or more embodiments described in this disclosure;

FIG. 6 depicts a generalized diagram of a chemical processing system utilized subsequent to the chemical pretreatment system where the upgraded heavy oil is introduced to a stream cracker, according to one or more embodiments described in this disclosure;

FIG. 7 depicts a generalized diagram of a chemical processing system utilized subsequent to the chemical pretreatment system where a light fraction of the upgraded heavy oil is introduced to a stream cracker and a heavy fraction of the upgraded heavy oil is recycled to the pretreatment system, according to one or more embodiments described in this disclosure; and

FIG. 8 depicts a generalized diagram of a chemical processing system utilized subsequent to the chemical pretreatment system where the upgraded heavy oil is directly introduced to a distillation column to recover transport fuels, according to one or more embodiments described in this disclosure.

For the purpose of the simplified schematic illustrations and descriptions of FIGS. 1-8, the numerous valves, temperature sensors, electronic controllers and the like that may be employed and are well known to those of ordinary skill in the art of certain chemical processing operations are not included. Further, accompanying components that are often included in conventional chemical processing operations are not depicted, such as refineries, air supplies, catalyst hoppers, and flue gas handling. It would be known that these components are within the spirit and scope of the present embodiments disclosed. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.

It should further be noted that arrows in the drawings refer to process streams. However, the arrows may equivalently refer to transfer lines that may serve to transfer process steams between two or more system components. Additionally, arrows that connect to system components define inlets or outlets in each given system component. The arrow direction corresponds generally with the major direction of movement of the materials of the stream contained within the physical transfer line signified by the arrow. Furthermore, arrows that do not connect two or more system components signify a product stream which may exit the depicted system or a system inlet stream which may enter the depicted system. Product streams may be further processed in accompanying chemical processing systems or may be commercialized as end products. System inlet streams may be streams transferred from accompanying chemical processing systems or may be non-processed feedstock streams. Additionally, dashed or dotted lines may signify an optional step or stream. For example, recycle streams in a system may be optional. However, it should be appreciated that not all solid lines may represent required transfer lines or chemical streams.

Reference will now be made in greater detail to various embodiments, some embodiments of which are illustrated in the accompanying drawings. Whenever possible, the same reference numerals will be used throughout the drawings to refer to the same or similar parts.

DETAILED DESCRIPTION

Generally, described in this disclosure are various embodiments of systems and methods for processing heavy oils such as crude oil. According to one or more embodiments, the heavy oil processing may include an upgrading process followed by downstream processing, for example, steam cracking. Generally, the upgrading process may remove one or more of at least a portion of nitrogen, sulfur, and one or more metals from the heavy oil and may additionally break aromatic moieties in the heavy oil. According to one or more embodiments, the heavy oil may be treated with a hydrodemetalization catalyst (referred to sometimes in this disclosure as an “HDM catalyst”), a transition catalyst, a hydrodenitrogenation catalyst (referred to sometimes in this disclosure as an “HDN catalyst”), a first hydrocracking catalyst, and a second hydrocracking catalyst. As described herein, the “first hydrocracking catalyst” and the “second hydrocracking catalyst” are not the same catalyst. For example, they may vary by composition, porosity, or both. However, it should be understood that “first” and “second” do not necessarily refer to positioning with the described systems. The HDM catalyst, transition catalyst, HDN catalyst, first hydrocracking catalyst, and second hydrocracking catalyst may be positioned in series, either contained in a single reactor, such as a packed bed reactor with multiple beds, or contained in two or more reactors arranged in series.

Embodiments of the pretreatment process, as well as other processes following the pretreatment process, are described herein. The systems that may be utilized following the pretreatment may be referred to as a “chemical processing system,” or alternatively as a “post-pretreatment process” or “downstream processing.” It should be understood that any of the disclosed chemical processing systems may be practiced in conjunction with any of the pretreatment processes described herein. For example, FIGS. 1-3 depict embodiments of pretreatment processing, and FIGS. 4-8 depict embodiments of chemical processing systems (for example, post-pretreatment processing) by steam cracking. It should be appreciated that any of the embodiments of the pretreatment systems, such as those depicted in FIGS. 1-3 or described with respect to FIGS. 1-3, may be utilized with any of the downstream processing configurations described herein, such as those of any of FIGS. 4-8, or any other processing configuration described with respect to FIGS. 4-8.

As used in this disclosure, a “reactor” refers to any vessel, container, or the like, in which one or more chemical reactions may occur between one or more reactants optionally in the presence of one or more catalysts. For example, a reactor may include a tank or tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (CSTR), or a plug flow reactor. Example reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. One or more “reaction zones” may be disposed in a reactor. As used in this disclosure, a “reaction zone” refers to an area where a particular reaction takes place in a reactor. For example, a packed bed reactor with multiple catalyst beds may have multiple reaction zones, where each reaction zone is defined by the area of each catalyst bed.

As used in this disclosure, a “separation unit” refers to any separation device that at least partially separates one or more chemicals that are mixed in a process stream from one another. For example, a separation unit may selectively separate differing chemical species from one another, forming one or more chemical fractions. Examples of separation units include, without limitation, distillation columns, flash drums, knock-out drums, knock-out pots, centrifuges, filtration devices, traps, scrubbers, expansion devices, membranes, solvent extraction devices, and the like. It should be understood that separation processes described in this disclosure may not completely separate all of one chemical consistent from all of another chemical constituent. It should be understood that the separation processes described in this disclosure “at least partially” separate different chemical components from one another, and that even if not explicitly stated, it should be understood that separation may include only partial separation. As used in this disclosure, one or more chemical constituents may be “separated” from a process stream to form a new process stream. Generally, a process stream may enter a separation unit and be divided or separated into two or more process streams of desired composition. Further, in some separation processes, a “light fraction” and a “heavy fraction” may separately exit the separation unit. In general, the light fraction stream has a lesser boiling point than the heavy fraction stream. It should be additionally understood that where only one separation unit is depicted in a figure or described, two or more separation units may be employed to carry out the identical or substantially identical separation. For example, where a distillation column with multiple outlets is described, it is contemplated that several separators arranged in series may equally separate the feed stream and such embodiments are within the scope of the presently described embodiments.

It should be understood that a “reaction effluent” generally refers to a stream that exits a separation unit, a reactor, or reaction zone following a particular reaction or separation. Generally, a reaction effluent has a different composition than the stream that entered the separation unit, reactor, or reaction zone. It should be understood that when an effluent is passed to another system unit, only a portion of that system stream may be passed. For example, a slip stream may carry some of the effluent away, meaning that only a portion of the effluent enters the downstream system unit.

As used in this disclosure, a “catalyst” refers to any substance that promotes the rate of a specific chemical reaction. Catalysts described in this disclosure may be utilized to promote various reactions, such as, but not limited to, hydrodemetalization, hydrodesulfurization, hydrodenitrogenation, hydrodearomatization, aromatic cracking, or combinations thereof. As used in this disclosure, “cracking” generally refers to a chemical reaction where a molecule having carbon-carbon bonds is broken into more than one molecule by the breaking of one or more of the carbon-carbon bonds; where a compound including a cyclic moiety, such as an aromatic, is converted to a compound that does not include a cyclic moiety; or where a molecule having carbon-carbon double bonds are reduced to carbon-carbon single bonds. Some catalysts may have multiple forms of catalytic activity, and calling a catalyst by one particular function does not render that catalyst incapable of being catalytically active for other functionality.

It should be understood that two or more process stream are “mixed” or “combined” when two or more lines intersect in the schematic flow diagrams of FIGS. 1-8. Mixing or combining may also include mixing by directly introducing both streams into a like reactor, separation unit, or other system component.

It should be understood that the reactions promoted by catalysts as described in this disclosure may remove a chemical constituent, such as only a portion of a chemical constituent, from a process stream. For example, a hydrodemetalization (HDM) catalyst may be present in an effective amount to promote a reaction that removes a portion of one or more metals from a process stream. A hydrodenitrogenation (HDN) catalyst may be present in an effective amount to promote a reaction that removes a portion of the nitrogen present in a process stream. A hydrodesulfurization (HDS) catalyst may be present in an effective amount to promote a reaction that removes a portion of the sulfur present in a process stream. Additionally, a first hydrocracking catalyst, such as a hydrodearomatization (HDA) catalyst, may be present in an effective amount to promote a reaction that reduces the amount of aromatic moieties in a process stream by saturating and cracking those aromatic moieties, and a second hydrocracking catalyst may be present in an effective amount to promote a reaction that further reduces the amount of aromatic moieties in the process stream following the first hydrocracking zone by further saturating and cracking aromatic moieties. It should be understood that, throughout this disclosure, a particular catalyst is not necessarily limited in functionality to the removal or cracking of a particular chemical constituent or moiety when it is referred to as having a particular functionality. For example, a catalyst identified in this disclosure as an HDN catalyst may additionally provide HDA functionality, HDS functionality, or both.

It should further be understood that streams may be named for the components of the stream, and the component for which the stream is named may be the major component of the stream (such as comprising from 50 weight percent (wt. %), from 70 wt. %, from 90 wt. %, from 95 wt. %, or even from 95 wt. % of the contents of the stream to 100 wt. % of the contents of the stream).

It should be understood that pore size, as used throughout this disclosure, relates to the average pore size unless specified otherwise. The average pore size may be determined from a Brunauer-Emmett-Teller (BET) analysis. Further, the average pore size may be confirmed by transmission electron microscope (TEM) characterization.

Referring now to FIG. 1, a pretreatment system 100 is depicted which includes a generalized hydrotreatment catalyst system 132. It should be understood that additional embodiments of the hydrotreatment catalyst system 132 of FIG. 1 are described in detail in FIGS. 2-3. However, it should be understood that the feedstocks, products, recycle streams, et cetera, of the generalized pretreatment system 100 of FIG. 1 apply also to embodiments described with respect to FIGS. 2-8.

Referring to FIG. 1, according to embodiments of this disclosure, a heavy oil feed stream 101 may be mixed with a hydrogen stream 104. The hydrogen stream 104 may comprise unspent hydrogen gas from recycled process gas component stream 113, make-up hydrogen from hydrogen feed stream 114, or both, to mix with heavy oil feed stream 101 and form a pretreatment catalyst input stream 105. In one or more embodiments, pretreatment catalyst input stream 105 may be heated to a process temperature of from 350 degrees Celsius (° C.) to 450° C. The pretreatment catalyst input stream 105 may enter and pass through the hydrotreatment catalyst system 132. As is described herein, the hydrotreatment catalyst system 132 may include a series of reaction zones, including a HDM reaction zone, a transition reaction zone, a HDN reaction zone, a first hydrocracking reaction zone, and a second hydrocracking reaction zone.

The systems and processes described are applicable for a wide variety of heavy oil feeds (in heavy oil feed stream 101), including crude oils, vacuum residue, tar sands, bitumen and vacuum gas oils using a catalytic hydrotreating pretreatment process. If the heavy oil feed is crude oil, it may have an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees. For example, the heavy oil feed utilized may be Arab Heavy crude oil. The typical properties for an Arab Heavy crude oil are shown in Table 1.

TABLE 1 Arab Heavy Export Feedstock Analysis Units Value American Petroleum Institute degree 27 (API) gravity Density grams per cubic centimeter 0.8904 (g/cm³) Sulfur Content Weight percent (wt. %) 2.83 Nickel Parts per million by weight 16.4 (ppmw) Vanadium ppmw 56.4 NaCl Content ppmw <5 Conradson Carbon wt. % 8.2 Residue (CCR) C5 Asphaltenes wt. % 7.8 C7 Asphaltenes wt. % 4.2

Still referring to FIG. 1, a pretreatment catalyst reaction effluent stream 109 may be formed by interaction of the pretreatment catalyst input stream 105 with hydrotreatment catalyst system 132. The pretreatment catalyst reaction effluent stream 109 may enter a separation unit 112 and may be separated into recycled process gas component stream 113 and intermediate liquid product stream 115. In one embodiment, the pretreatment catalyst reaction effluent stream 109 may also be purified to remove hydrogen sulfide and other process gases to increase the purity of the hydrogen to be recycled in recycled process gas component stream 113. The hydrogen consumed in the process can be compensated for by the addition of fresh hydrogen from make-up hydrogen feed stream 114, which may be derived from a steam or naphtha reformer or other source. Recycled process gas component stream 113 and make-up hydrogen feed stream 114 may combine to form hydrogen stream 104. In one embodiment, intermediate liquid product stream 115 may be separated in separation unit 116 to separate light hydrocarbon fraction stream 117 and pretreatment final liquid product stream 118; however, it should be understood that this separation step is optional. In further embodiments, separation unit 116 may be a flash vessel. In one embodiment, light hydrocarbon fraction stream 117 acts as a recycle and is mixed with fresh light hydrocarbon diluent stream 102 to create light hydrocarbon diluent stream 103. Fresh light hydrocarbon diluent stream 102 can be used as needed to provide make-up diluent to the process to help further reduce the deactivation of one or more of the catalysts in the hydrotreatment catalyst system 132.

In one or more embodiments, one or more of the pretreatment catalyst reaction effluent stream 109, the intermediate liquid product stream 115, and the pretreatment final liquid product stream 118 may have reduced aromatic content as compared with the heavy oil feed stream 101. Additionally, in embodiments, one or more of the pretreatment catalyst reaction effluent stream 109, the intermediate liquid product stream 115, and the pretreatment final liquid product stream 118 may have significantly reduced sulfur, metal, asphaltenes, Conradson carbon, nitrogen content, or combinations thereof, as well as an increased API gravity and increased diesel and vacuum distillate yields as compared to the heavy oil feed stream 101.

According to one or more embodiments, the pretreatment catalyst reaction effluent stream 109 may have a reduction of at least about 80 wt. %, a reduction of at least 90 wt. %, or even a reduction of at least 95 wt. % of nitrogen with respect to the heavy oil feed stream 101. According to another embodiment, the pretreatment catalyst reaction effluent stream 109 may have a reduction of at least about 85 wt. %, a reduction of at least 90 wt. %, or even a reduction of at least 99 wt. % of sulfur with respect to the heavy oil feed stream 101. According to another embodiment, the pretreatment catalyst reaction effluent stream 109 may have a reduction of at least about 70 wt. %, a reduction of at least 80 wt. %, or even a reduction of at least 85 wt. % of aromatic content with respect to the heavy oil feed stream 101. According to another embodiment, the pretreatment catalyst reaction effluent stream 109 may have a reduction of at least about 80 wt. %, a reduction of at least 90 wt. %, or even a reduction of at least 99 wt. % of metal with respect to the heavy oil feed stream 101.

Still referring to FIG. 1, in various embodiments, one or more of the pretreatment catalyst reaction effluent stream 109, the intermediate liquid product stream 115, and the pretreatment final liquid product stream 118 may be suitable for use as the upgraded oil stream 220 for downstream processing, embodiments of which are described subsequently in this disclosure. As used in this disclosure, one or more of the pretreatment catalyst reaction effluent stream 109, the intermediate liquid product stream 115, and the pretreatment final liquid product stream 118 may be referred to as an “upgraded oil” which may be downstream processed by the downstream systems of at least FIGS. 4-8. The upgraded oils, in some embodiments, may have a final boiling point of less than or equal to 540° C., which may increase efficiency or further conversion in downstream steam cracking. In additional embodiments, at least 90 wt. %, at least 95 wt. %, or even at least 99 wt. % of the upgraded oil may have a boiling point of less than or equal to 540° C. In additional embodiments, the upgraded oil may have a final boiling point of less than or equal to 520° C., 500° C., 480° C., 460° C., 440° C., 420° C., 400° C., 380° C., 360° C., 340° C., 320° C., or even 300° C. It should be understood that the final boiling point of the upgraded oil is equal to the final boiling point of the pretreatment reaction catalyst effluent stream 109 because only light fractions are removed by subsequent, optional separation steps in pretreatment system 100.

Referring now to FIG. 2, according to one or more embodiments, the hydrotreatment catalyst system 132 may include or consist of multiple packed bed reaction zones arranged in series (for example, a HDM reaction zone 106, a transition reaction zone 108, a HDN reaction zone 110, a first hydrocracking reaction zone 120, and a second hydrocracking reaction zone 125) and each of these reaction zones may comprise a catalyst bed. Each of these reaction zones may be contained in a single reactor as a packed bed reactor with multiple beds in series, as shown as a pretreatment reactor 130 in FIG. 2. In such embodiments, the pretreatment reactor 130 comprises an HDM catalyst bed comprising an HDM catalyst in the HDM reaction zone 106, a transition catalyst bed comprising a transition catalyst in the transition reaction zone 108, an HDN catalyst bed comprising an HDN catalyst in the HDN reaction zone 110, a first hydrocracking catalyst bed comprising a first hydrocracking catalyst in the hydrocracking reaction zone 120, and and a second hydrocracking catalyst bed comprising a second hydrocracking catalyst in the second hydrocracking reaction zone 125. In other embodiments, the HDM reaction zone 106, transition reaction zone 108, HDN reaction zone 110, and hydrocracking reaction zone 120 may each be contained in a plurality of packed bed reactors arranged in series. In further embodiments, each reaction zone is contained in a separate, single packed bed reactor. It should be understood that contemplated embodiments include those where packed catalyst beds which are arranged in series are contained in a single reactor or in multiple reactors each containing one or more catalyst beds. It should be appreciated that when relatively large quantities of catalyst are needed, it may be desirable to house those catalysts in separate reactors.).

According to one or more embodiments, the pretreatment catalyst input stream 105, which comprises heavy oil, is introduced to the HDM reaction zone 106 and is contacted by the HDM catalyst. Contact by the HDM catalyst with the pretreatment catalyst input stream 105 may promote a reaction that removes at least a portion of the metals present in the pretreatment catalyst input stream 105. Following contact with the HDM catalyst, the pretreatment catalyst input stream 105 may be converted to an HDM reaction effluent. The HDM reaction effluent may have a reduced metal content as compared to the contents of the pretreatment catalyst input stream 105. For example, the HDM reaction effluent may have at least 70 wt. % less, at least 80 wt. % less, or even at least 95 wt. % less metal as the pretreatment catalyst input stream 105.

According to one or more embodiments, the HDM reaction zone 106 may have a weighted average bed temperature of from 350° C. to 450° C., such as from 370° C. to 415° C., and may have a pressure of from 30 bars to 200 bars, such as from 90 bars to 110 bars. The HDM reaction zone 106 comprises the HDM catalyst, and the HDM catalyst may fill the entirety of the HDM reaction zone 106.

The HDM catalyst may comprise one or more metals from the International Union of Pure and Applied Chemistry (IUPAC) Groups 5, 6, or 8-10 of the periodic table. For example, the HDM catalyst may comprise molybdenum. The HDM catalyst may further comprise a support material, and the metal may be disposed on the support material. In one embodiment, the HDM catalyst may comprise a molybdenum metal catalyst on an alumina support (sometimes referred to as “Mo/Al₂O₃ catalyst”). It should be understood throughout this disclosure that metals contained in any of the disclosed catalysts may be present as sulfides or oxides, or even other compounds.

In one embodiment, the HDM catalyst may include a metal sulfide on a support material, where the metal is selected from the group consisting of IUPAC Groups 5, 6, and 8-10 elements of the periodic table, and combinations thereof. The support material may be gamma-alumina or silica/alumina extrudates, spheres, cylinders, beads, pellets, and combinations thereof.

In one embodiment, the HDM catalyst may comprise a gamma-alumina support, with a surface area of from 100 m²/g to 160 m²/g (such as, from 100 m²/g to 130 m²/g, or from 130 m²/g to 160 m²/g). The HDM catalyst can be best described as having a relatively large pore volume, such as at least 0.8 cm³/g (for example, at least 0.9 cm³/g, or even at least 1.0 cm³/g). The pore size of the HDM catalyst may be predominantly macroporous (that is, having a pore size of greater than 50 nm). This may provide a large capacity for the uptake of metals on the HDM catalyst's surface and optionally dopants. In one embodiment, a dopant can be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

In one or more embodiments, the HDM catalyst may comprise from 0.5 wt. % to 12 wt. % of an oxide or sulfide of molybdenum (such as from 2 wt. % to 10 wt. % or from 3 wt. % to 7 wt. % of an oxide or sulfide of molybdenum), and from 88 wt. % to 99.5 wt. % of alumina (such as from 90 wt. % to 98 wt. % or from 93 wt. % to 97 wt. % of alumina).

Without being bound by theory, in some embodiments, it is believed that during the reaction in the HDM reaction zone 106, the HDM catalyst promotes the hydrogenation of porphyrin type compounds present in the heavy oil via hydrogen to create an intermediate. Following this primary hydrogenation, the nickel or vanadium present in the center of the porphyrin molecule in the intermediate is reduced with hydrogen and then further reduced to the corresponding sulfide with hydrogen sulfide (H₂S). The final metal sulfide is deposited on the HDM catalyst, thus removing the metal sulfide from the virgin crude oil. Sulfur is also removed from sulfur-containing organic compounds through a parallel pathway. The rates of these parallel reactions may depend upon the sulfur species being considered. Overall, hydrogen is used to abstract the sulfur, which is converted to H₂S in the process. The remaining, sulfur-free hydrocarbon fragments remain in the liquid hydrocarbon stream.

The HDM reaction effluent may be passed from the HDM reaction zone 106 to the transition reaction zone 108 where it is contacted by the transition catalyst. Contact by the transition catalyst with the HDM reaction effluent may promote a reaction that removes at least a portion of the metals present in the HDM reaction effluent stream as well as reactions that may remove at least a portion of the nitrogen present in the HDM reaction effluent stream. Following contact with the transition catalyst, the HDM reaction effluent is converted to a transition reaction effluent. The transition reaction effluent may have a reduced metal content and nitrogen content as compared to the HDM reaction effluent. For example, the transition reaction effluent may have at least 50 wt. % less, at least 80 wt. % less, or even at least 90 wt. % less metal content as the HDM reaction effluent. Additionally, the transition reaction effluent may have at least 10 wt. % less, at least 15 wt. % less, or even at least 20 wt. % less nitrogen as the HDM reaction effluent.

According to embodiments, the transition reaction zone 108 has a weighted average bed temperature of about 370° C. to 410° C. The transition reaction zone 108 comprises the transition catalyst, and the transition catalyst may fill the entirety of the transition reaction zone 108.

In one embodiment, the transition reaction zone 108 may be operable to remove a quantity of metal components and a quantity of sulfur components from the HDM reaction effluent stream. The transition catalyst may comprise an alumina based support in the form of extrudates.

In one embodiment, the transition catalyst comprises one metal from IUPAC Group 6 and one metal from IUPAC Groups 8-10. Example IUPAC Group 6 metals include molybdenum and tungsten. Examples of IUPAC Group 8-10 metals include nickel and cobalt. For example, the transition catalyst may comprise Mo and Ni on a titania support (sometimes referred to as a “Mo—Ni/Al₂O₃ catalyst”). The transition catalyst may also contain a dopant that is selected from the group consisting of boron, phosphorus, halogens, silicon, and combinations thereof. The transition catalyst can have a surface area of 140 m²/g to 200 m²/g (such as from 140 m²/g to 170 m²/g or from 170 m²/g to 200 m²/g). The transition catalyst can have an intermediate pore volume of from 0.5 cm³/g to 0.7 cm³/g (such as 0.6 cm³/g). The transition catalyst may generally comprise a mesoporous structure having pore sizes in the range of 12 nm to 50 nm. These characteristics provide a balanced activity in HDM and HDS.

In one or more embodiments, the transition catalyst may comprise from 10 wt. % to 18 wt. % of an oxide or sulfide of molybdenum (such as from 11 wt. % to 17 wt. % or from 12 wt. % to 16 wt. % of an oxide or sulfide of molybdenum), from 1 wt. % to 7 wt. % of an oxide or sulfide of nickel (such as from 2 wt. % to 6 wt. % or from 3 wt. % to 5 wt. % of an oxide or sulfide of nickel), and from 75 wt. % to 89 wt. % of alumina (such as from 77 wt. % to 87 wt. % or from 79 wt. % to 85 wt. % of alumina).

The transition reaction effluent may be passed from the transition reaction zone 108 to the HDN reaction zone 110 where it is contacted by the HDN catalyst. Contact by the HDN catalyst with the transition reaction effluent may promote a reaction that removes at least a portion of the nitrogen present in the transition reaction effluent stream. Following contact with the HDN catalyst, the transition reaction effluent may be converted to an HDN reaction effluent. The HDN reaction effluent may have a reduced metal content and nitrogen content as compared to the transition reaction effluent. For example, the HDN reaction effluent may have a nitrogen content reduction of at least 80 wt. %, at least 85 wt. %, or even at least 90 wt. % relative to the transition reaction effluent. In another embodiment, the HDN reaction effluent may have a sulfur content reduction of at least 80 wt. %, at least 90 wt. %, or even at least 95 wt. % relative to the transition reaction effluent. In another embodiment, the HDN reaction effluent may have an aromatics content reduction of at least 25 wt. %, at least 30 wt. %, or even at least 40 wt. % relative to the transition reaction effluent.

According to embodiments, the HDN reaction zone 110 has a weighted average bed temperature of from 370° C. to 410° C. The HDN reaction zone 110 comprises the HDN catalyst, and the HDN catalyst may fill the entirety of the HDN reaction zone 110.

In one embodiment, the HDN catalyst includes a metal oxide or sulfide on a support material, where the metal is selected from the group consisting of IUPAC Groups 5, 6, and 8-10 of the periodic table, and combinations thereof. The support material may include gamma-alumina, meso-porous alumina, silica, or both, in the form of extrudates, spheres, cylinders and pellets.

According to one embodiment, the HDN catalyst contains a gamma alumina based support that has a surface area of 180 m²/g to 240 m²/g (such as from 180 m²/g to 210 m²/g, or from 210 m²/g to 240 m²/g). This relatively large surface area for the HDN catalyst allows for a smaller pore volume (for example, less than 1.0 cm³/g, less than 0.95 cm³/g, or even less than 0.9 cm³/g). In one embodiment, the HDN catalyst contains at least one metal from IUPAC Group 6, such as molybdenum and at least one metal from IUPAC Groups 8-10, such as nickel. The HDN catalyst can also include at least one dopant selected from the group consisting of boron, phosphorus, silicon, halogens, and combinations thereof. In one embodiment, the HDN catalyst may include cobalt, which further promotes desulfurization. In one embodiment, the HDN catalyst has a higher metals loading for the active phase as compared to the HDM catalyst. This increased metals loading may cause increased catalytic activity. In one embodiment, the HDN catalyst comprises nickel and molybdenum, and has a nickel to molybdenum mole ratio (Ni/(Ni+Mo)) of 0.1 to 0.3 (such as from 0.1 to 0.2 or from 0.2 to 0.3). In an embodiment that includes cobalt, the mole ratio of (Co+Ni)/Mo may be in the range of 0.25 to 0.85 (such as from 0.25 to 0.5 or from 0.5 to 0.85).

According to another embodiment, the HDN catalyst may contain a mesoporous material, such as mesoporous alumina, that may have an average pore size of at least 25 nm. For example, the HDN catalyst may comprise mesoporous alumina having an average pore size of at least 30 nm, or even at least 35 nm. HDN catalysts with relatively small average pore size, such as less than 2 nm, may be referred to as conventional HDN catalysts in this disclosure, and may have relatively poor catalytic performance as compared with the presently disclosed HDN catalysts with larger-sized pores. Embodiments of HDN catalysts with an alumina support having an average pore size of from 2 nm to 50 nm may be referred to in this disclosure as “meso-porous alumina supported catalysts.” In one or more embodiments, the mesoporous alumina of the HDM catalyst may have an average pore size in a range from 2 nm to 50 nm, 25 nm to 50 nm, from 30 nm to 50 nm, or from 35 nm to 50 nm. According to embodiments, the HDN catalyst may include alumina that has a relatively large surface area, a relatively large pore volume, or both. For example, the mesoporous alumina may have a relatively large surface area by having a surface area of at least about 225 m²/g, at least about 250 m²/g, at least about 275 m²/g, at least about 300 m²/g, or even at least about 350 m²/g, such as from 225 m²/g to 500 m²/g, from 200 m²/g to 450 m²/g, or from 300 m²/g to 400 m²/g. In one or more embodiments, the mesoporous alumina may have a relatively large pore volume by having a pore volume of at least about 1 mL/g, at least about 1.1 mL/g, at least 1.2 mL/g, or even at least 1.2 mL/g, such as from 1 mL/g to 5 mL/g, from 1.1 mL/g to 3, or from 1.2 mL/g to 2 mL/g. Without being bound by theory, it is believed that the meso-porous alumina supported HDN catalyst may provide additional active sites and larger pore channels that may facilitate larger molecules to be transferred into and out of the catalyst. The additional active sites and larger pore channels may result in higher catalytic activity, longer catalyst life, or both. In one embodiment, the HDN catalyst may include a dopant, which can be selected from the group consisting of boron, silicon, halogens, phosphorus, and combinations thereof.

According to embodiments described, the HDN catalyst may be produced by mixing a support material, such as alumina, with a binder, such as acid peptized alumina. Water or another solvent may be added to the mixture of support material and binder to form an extrudable phase, which is then extruded into a desired shape. The extrudate may be dried at an elevated temperature (such as above 100° C., such as 110° C.) and then calcined at a suitable temperature (such as at a temperature of at least 400° C. or at least 450° C., such as 500° C.). The calcined extrudates may be impregnated with an aqueous solution containing catalyst precursor materials, such as precursor materials that include Mo, Ni, or combinations thereof. For example, the aqueous solution may contain ammonium heptanmolybdate, nickel nitrate, and phosphoric acid to form an HDN catalyst comprising compounds comprising molybdenum, nickel, and phosphorous.

In embodiments where a meso-porous alumina support is utilized, the meso-porous alumina may be synthesized by dispersing boehmite powder in water at 60° C. to 90° C. Then, an acid such as HNO₃ may be added to the boehmite in water solution at a ratio of HNO₃:Al³⁺ of 0.3 to 3.0 and the solution is stirred at 60° C. to 90° C. for several hours, such as 6 hours, to obtain a sol. A copolymer, such as a triblock copolymer, may be added to the sol at room temperature, where the molar ratio of copolymer:Al is from 0.02 to 0.05 and aged for several hours, such as three hours. The sol/copolymer mixture is dried for several hours and then calcined.

According to one or more embodiments, the HDN catalyst may comprise from 10 wt. % to 18 wt. % of an oxide or sulfide of molybdenum (such as from 13 wt. % to 17 wt. % or from 14 wt. % to 16 wt. % of an oxide or sulfide of molybdenum), from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel (such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide or sulfide of nickel), and from 74 wt. % to 88 wt. % of alumina (such as from 76 wt. % to 84 wt. % or from 78 wt. % to 82 wt. % of alumina).

In a similar manner to the HDM catalyst, and again not intending to be bound to any theory, it is believed that hydrodenitrogenation and hydrodearomatization may operate via related reaction mechanisms. Both involve some degree of hydrogenation. For the hydrodenitrogenation, organic nitrogen compounds are usually in the form of heterocyclic structures, the heteroatom being nitrogen. These heterocyclic structures may be saturated prior to the removal of the heteroatom of nitrogen. Similarly, hydrodearomatization involves the saturation of aromatic rings. Each of these reactions may occur to a differing extending depending on the amount or type of each of the catalysts because each catalyst may selectively promote one type of transfer over others and because the transfers are competing.

It should be understood that some embodiments of the presently-described methods and systems may utilize HDN catalyst that include porous alumina having an average pore size of at least 25 nm. However, in other embodiments, the average pore size of the porous alumina may be less than about 25 nm, and may even be microporous (that is, having an average pore size of less than 2 nm).

Still referring to FIG. 2, the HDN reaction effluent may be passed from the HDN reaction zone 110 to the first hydrocracking reaction zone 120 where it is contacted by the first hydrocracking catalyst. Contact by the first hydrocracking catalyst with the HDN reaction effluent may promote a reaction that reduces the aromatic content present in the HDN reaction effluent. Following contact with the first hydrocracking catalyst, the HDN reaction effluent is converted to a primary hydrocracking reaction effluent. The primary hydrocracking reaction effluent may have a reduced aromatics content as compared to the HDN reaction effluent. For example, the primary hydrocracking reaction effluent may have at least 50 wt. % less, at least 60 wt. % less, or even at least 80 wt. % less aromatics content as the HDN reaction effluent.

The first hydrocracking catalyst may comprise one or more metals from IUPAC Groups 5, 6, 8, 9, or 10 of the periodic table. For example, the first hydrocracking catalyst may comprise one or more metals from IUPAC Groups 5 or 6, and one or more metals from IUPAC Groups 8, 9, or 10 of the periodic table. For example, the first hydrocracking catalyst may comprise molybdenum or tungsten from IUPAC Group 6 and nickel or cobalt from IUPAC Groups 8, 9, or 10. The first hydrocracking catalyst may further comprise a support material, such as zeolite, and the metal may be disposed on the support material. In one embodiment, the first hydrocracking catalyst may comprise tungsten and nickel metal catalyst on a zeolite support that is mesoporous (sometimes referred to as “W—Ni/meso-zeolite catalyst”). In another embodiment, the first hydrocracking catalyst may comprise molybdenum and nickel metal catalyst on a zeolite support that is mesoporous (sometimes referred to as “Mo—Ni/meso-zeolite catalyst”).

According to embodiments of the first hydrocracking catalysts of the hydrotreatment catalytic systems described in this disclosure, the support material (that is, the mesoporous zeolite) may be characterized as mesoporous by having average pore size of from 2 nm to 50 nm. By way of comparison, conventional zeolite-based hydrocracking catalysts contain zeolites that are microporous, meaning that they have an average pore size of less than 2 nm. Without being bound by theory, it is believed that the relatively large-sized pores (that is, mesoporosity) of the presently-described first hydrocracking catalysts allow for larger molecules to diffuse inside the zeolite, which are believed to enhance the reaction activity and selectivity of the catalyst. Because of the increased pore size, aromatic-containing molecules can more easily diffuse into the catalyst and aromatic cracking may increase. For example, in some conventional embodiments, the feedstock converted by the hydroprocessing catalysts may be vacuum gas oils; light cycle oils from, for example, a fluid catalytic cracking reactor; or coker gas oils from, for example, a coking unit. The molecular sizes in these oils are relatively small compared to those of heavy oils such as crude and atmosphere residue, which may be the feedstock of the present methods and systems. The heavy oils generally are unable to diffuse inside the conventional zeolites and be converted on the active sites located inside the zeolites. Therefore, zeolites with larger pore sizes (that is, mesoporous zeolites) may allow the larger molecules of heavy oils to overcome the diffusion limitation, and may promote the reaction and conversion of the larger molecules of the heavy oils.

The zeolite support material of the first hydrocracking catalyst is not necessarily limited to a particular type of zeolite. However, it is contemplated that zeolites such as Y, Beta, AWLZ-15, LZ-45, Y-82, Y-84, LZ-210, LZ-25, Silicalite, or mordenite may be suitable for use in the presently-described first hydrocracking catalyst. For example, suitable mesoporous zeolites that can be impregnated with one or more catalytic metals such as W, Ni, Mo, or combinations thereof, are described in at least U.S. Pat. No. 7,785,563; Zhang et al., Powder Technology 183 (2008) 73-78; Liu et al., Microporous and Mesoporous Materials 181 (2013) 116-122; and Garcia-Martinez et al., Catalysis Science & Technology, 2012 (DOI: 10.1039/c2cy00309k).

In one or more embodiments, the first hydrocracking catalyst may comprise from 18 wt. % to 28 wt. % of a sulfide or oxide of tungsten (such as from 20 wt. % to 27 wt. % or from 22 wt. % to 26 wt. % of tungsten or a sulfide or oxide of tungsten), from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel (such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide or sulfide of nickel), and from 5 wt. % to 40 wt. % of mesoporous zeolite (such as from 10 wt. % to 35 wt. % or from 10 wt. % to 30 wt. % of zeolite). In another embodiment, the first hydrocracking catalyst may comprise from 12 wt. % to 18 wt. % of an oxide or sulfide of molybdenum (such as from 13 wt. % to 17 wt. % or from 14 wt. % to 16 wt. % of an oxide or sulfide of molybdenum), from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel (such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide or sulfide of nickel), and from 5 wt. % to 40 wt. % of mesoporous zeolite (such as from 10 wt. % to 35 wt. % or from 10 wt. % to 30 wt. % of mesoporous zeolite).

The first hydrocracking catalysts described may be prepared by selecting a mesoporous zeolite and impregnating the mesoporous zeolite with one or more catalytic metals or by comulling mesoporous zeolite with other components. For the impregnation method, the mesoporous zeolite, active alumina (for example, boehmite alumina), and binder (for example, acid peptized alumina) may be mixed. An appropriate amount of water may be added to form a dough that can be extruded using an extruder. The extrudate may be dried at from 80° C. to 120° C. for from 4 hours to 10 hours and then calcinated at from 500° C. to 550° C. for from 4 hours to 6 hours. The calcinated extrudate may be impregnated with an aqueous solution prepared with compounds comprising Ni, W, Mo, Co, or combinations thereof. Two or more catalytic metal precursors may be utilized when two catalytic metals are desired. However, some embodiments may include only one of Ni, W, Mo, or Co. For example, the catalyst support material may be impregnated by a mixture of nickel nitrate hexahydrate (that is, Ni(NO₃)2.6H₂O) and ammonium metatungstate (that is, (NH₄)6H₂W₁₂O₄₀) if a W—Ni hydrocracking catalyst is desired. The impregnated extrudate may be dried at from 80° C. to 120° C. for from 4 hours to 10 hours and then calcinated at from 450° C. to 500° C. for from 4 hours to 6 hours. For the comulling method, the mesoporous zeolite may be mixed with alumina, binder, and the compounds comprising W or Mo, Ni or Co (for example, MoO₃ or nickel nitrate hexahydrate if Mo—Ni is desired).

It should be understood that some embodiments of the presently-described methods and systems may utilize a first hydrocracking catalyst that includes a mesoporous zeolite (that is, having an average pore size of from 2 nm to 50 nm). However, in other embodiments, the average pore size of the zeolite may be less than 2 nm (that is, microporous).

Still referring to FIG. 2, the primary hydrocracking reaction effluent may be passed from the first hydrocracking reaction zone 120 to the second hydrocracking reaction zone 125 where it is contacted by the second hydrocracking catalyst. Contact by the second hydrocracking catalyst with the primary hydrocracking reaction effluent may promote a reaction that reduces aromatic content present in the primary hydrocracking reaction effluent, which may include vacuum gas oils and middle distillate. Following contact with the second hydrocracking catalyst, the primary hydrocracking reaction effluent is converted to a pretreatment catalyst reaction effluent stream 109. The pretreatment catalyst reaction effluent stream 109 may have a reduced aromatics content as compared to the primary hydrocracking reaction effluent. For example, the pretreatment catalyst reaction effluent stream 109 may have at least 10 wt. % less, at least 50 wt. % less, or even at least 80 wt. % less aromatics content as the primary hydrocracking reaction effluent.

The second hydrocracking catalyst may comprise one or more metals from IUPAC Groups 5, 6, 8, 9, or 10 of the periodic table. For example, the second hydrocracking catalyst may comprise one or more metals from IUPAC Groups 5 or 6, and one or more metals from IUPAC Groups 8, 9, or 10 of the periodic table. For example, the second hydrocracking catalyst may comprise molybdenum or tungsten from IUPAC Group 6 and nickel or cobalt from IUPAC Groups 8, 9, or 10. The second hydrocracking catalyst may further comprise a support material, such as zeolite, and the metal may be disposed on the support material. In one embodiment, the second hydrocracking catalyst may comprise tungsten and nickel metal catalyst on a zeolite support. In another embodiment, the second hydrocracking catalyst may comprise molybdenum and nickel metal catalyst on a zeolite support. The second hydrocracking catalyst may further comprise alumina.

According to embodiments of the second hydrocracking catalysts of the hydrotreatment catalyst systems described in this disclosure, when compared to the first hydrocracking catalysts described herein, the second hydrocracking catalysts may have one or more of a smaller average pore size, a lesser pore volume, a greater surface area, or greater acidity. In additional embodiments, the second hydrocracking catalyst may include more microporosity than the first hydrocracking catalyst and be substantially free of mesopores. In additional embodiments, the average pore size of the second hydrocracking catalyst may be less than the first hydrocracking catalyst by virtue of the second hydrocracking catalyst being substantially free of mesopores (2-50 nm) while the first hydrocracking catalyst includes mesopores. Without being bound by theory, it is believed that greater acidity and desired pore structure of the second hydrocracking catalysts allow the second hydrocracking catalysts to be better suited to promote reactions to convert the size of the molecules of vacuum gas oils. Because of the pore size, molecules of vacuum gas oils can more easily diffuse into the second hydrocracking catalyst and aromatic cracking may increase. For example, in some conventional embodiments, the feedstock converted by the second hydrocracking catalysts may be light cycle oils from, for example, a fluid catalytic cracking reactor; or coker gas oils from, for example, a coking unit. The molecular sizes in these oils are relatively small compared to those of heavy oils, such as crude and atmosphere residue, and vacuum gas oils, which may be the feedstock of the present methods and systems.

In one or more embodiments, a zeolite support material may be utilized for the second hydrocracking catalyst and is not necessarily limited to a particular type of zeolite. However, it is contemplated that zeolites such as Y, Beta, AWLZ-15, LZ-45, Y-82, Y-84, LZ-210, LZ-25, Silicalite, or mordenite may be suitable for use in the presently-described second hydrocracking catalyst. As referenced previously in this disclosure, for example, suitable mesoporous zeolites that can be impregnated with one or more catalytic metals such as W, Ni, Mo, or combinations thereof, are described in at least U.S. Pat. No. 7,785,563; Zhang et al., Powder Technology 183 (2008) 73-78; Liu et al., Microporous and Mesoporous Materials 181 (2013) 116-122; and Garcia-Martinez et al., Catalysis Science & Technology, 2012 (DOI: 10.1039/c2cy00309k).

In one or more embodiments, the second hydrocracking catalyst may comprise from 20 wt. % to 25 wt. % of a sulfide or oxide of tungsten (such as from 20 wt. % to 23 wt. % or from 22 wt. % to 25 wt. % of tungsten or a sulfide or oxide of tungsten), from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel (such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide or sulfide of nickel), and from 20 wt. % to 60 wt. % of mesoporous zeolite (such as from 20 wt. % to 40 wt. % or from 40 wt. % to 60 wt. % of zeolite). In another embodiment, the second hydrocracking catalyst may comprise from 12 wt. % to 18 wt. % of an oxide or sulfide of molybdenum (such as from 13 wt. % to 17 wt. % or from 14 wt. % to 16 wt. % of an oxide or sulfide of molybdenum), from 2 wt. % to 8 wt. % of an oxide or sulfide of nickel (such as from 3 wt. % to 7 wt. % or from 4 wt. % to 6 wt. % of an oxide or sulfide of nickel), and from 20 wt. % to 60 wt. % of mesoporous zeolite (such as from 20 wt. % to 40 wt. % or from 40 wt. % to 60 wt. % of zeolite).

The second hydrocracking catalysts described may be prepared by selecting a zeolite and impregnating the zeolite with one or more catalytic metals or by comulling zeolite with other components. For the impregnation method, the zeolite, active alumina (for example, boehmite alumina), and binder (for example, acid peptized alumina) may be mixed. An appropriate amount of water may be added to form a dough that can be extruded using an extruder. The extrudate may be dried at from 80° C. to 120° C. for from 4 hours to 10 hours and then calcinated at from 500° C. to 550° C. for from 4 hours to 6 hours. The calcinated extrudate may be impregnated with an aqueous solution prepared with compounds comprising Ni, W, Mo, Co, or combinations thereof. Two or more catalytic metal precursors may be utilized when two catalytic metals are desired. However, some embodiments may include only one of Ni, W, Mo, or Co. For example, the catalyst support material may be impregnated by a mixture of nickel nitrate hexahydrate (that is, Ni(NO₃)2.6H₂O) and ammonium metatungstate (that is, (NH₄)6H₂W₁₂O₄₀) if a W—Ni hydrocracking catalyst is desired. The impregnated extrudate may be dried at from 80° C. to 120° C. for from 4 hours to 10 hours and then calcinated at from 450° C. to 500° C. for from 4 hours to 6 hours. For the comulling method, the mesoporous zeolite may be mixed with alumina, binder, and the compounds comprising W or Mo, Ni or Co (for example, MoO₃ or nickel nitrate hexahydrate if Mo—Ni is desired).

It should be understood that some embodiments of the presently-described methods and systems may utilize a second hydrocracking catalyst that includes a microporous zeolite (that is, having an average pore size of less than 2 nm). However, in other embodiments, the average pore size of the zeolite may be 2 nm to 50 nm (that is, mesoporous).

According to one or more embodiments described, the volumetric ratio of HDM catalyst:transition catalyst:HDN catalyst:hydrocracking catalyst:second hydrocracking catalyst may be 5-20:5-30:30-70:5-30:5-30. The ratio of catalysts may depend at least partially on the metal content in the oil feedstock processed.

According to additional embodiments, the hydrotreatment catalyst system 132 may comprise the upstream packed bed hydrotreating reactor 134 and one or more additional downstream reactors. For example, the downstream reactor may include a tank or tubular reactor configured to operate as a batch reactor, a continuous stirred-tank reactor (CSTR), or a plug flow reactor. Example reactors include packed bed reactors such as fixed bed reactors, and fluidized bed reactors. The downstream reactor or reactors may have one or more reaction zones, including the first hydrocracking reaction zone 120 and the second hydrocracking reaction zone 125. The upstream packed bed hydrotreating reactor 134 may include the HDM reaction zone 106, the transition reaction zone 108, and the HDN reaction zone 110. In such embodiments, the HDM reaction zone 106, the transition reaction zone 108, the HDN reaction zone 110, the first hydrocracking reaction zone 120, and the second hydrocracking reaction zone 125 may utilize the respective catalysts, processing conditions, et cetera, disclosed with respect to the system of FIG. 2. In such embodiments, the configuration of the hydrotreatment catalyst system 132 may be particularly beneficial when reaction conditions such as, but not limited to, hydrogen content, temperature, or pressure are different for operation of the upstream packed bed hydrotreating reactor 134 and the downstream one or more reactors. Embodiments that may include one or more fluidized bed reactors may be beneficial with particular first hydrocracking catalysts, the second hydrocracking catalysts, or both as compared to the packed bed configurations.

Now referring to FIG. 3, according to additional embodiments, the hydrotreatment catalyst system 132 may include multiple packed bed reaction zones arranged in series (for example, a HDM reaction zone 106, a transition reaction zone 108, and a HDN reaction zone 110) and each of these reaction zones may comprise a catalyst bed. Each of these zones may be contained in a single reactor as a packed bed reactor with multiple beds in series, shown as an upstream packed bead hydrotreating reactor 134 in FIG. 3, and a downstream packed bed hydrocracking reactor 136. In other embodiments, the HDM reaction zone 106, the transition reaction zone 108, and the HDN reaction zone 110 may be contained in a plurality of packed bed reactors arranged in series with a downstream packed bed hydrocracking reactor 136. In further embodiments, each reaction zone is contained in a separate, single packed bed reactor. The upstream packed bed hydrotreating reactor 134 or plurality of upstream packed bed reactors may include the HDM reaction zone 106, the transition reaction zone 108, and the HDN reaction zone 110. The downstream packed bed hydrocracking reactor 136 may include the first hydrocracking reaction zone 120 and the second hydrocracking reaction zone 125. In such embodiments, the HDM reaction zone 106, the transition reaction zone 108, the HDN reaction zone 110, the first hydrocracking reaction zone 120, and the second hydrocracking reaction zone 125 may utilize the respective catalysts, processing conditions, et cetera, disclosed with respect to the system of FIG. 2. The configuration of the upstream packed bed hydrotreating reactor 134 or plurality of upstream packed bed reactors of FIG. 3 may be particularly beneficial when reaction conditions such as, but not limited to, hydrogen content, temperature, or pressure are different for operation of the upstream packed bed hydrotreating reactor 134 or plurality of upstream packed bed reactors and the downstream packed bed hydrocracking reactor 136. In such embodiments, a stream 131 is passed from the upstream packed bed hydrotreating reactor 134 or plurality of upstream packed bed reactors to the downstream packed bed hydrocracking reactor 136.

It should be understood that other reactor configurations are contemplated, such as each catalyst in a separate reactor or one or more catalysts sharing a reactor. The various reactors may operate as packed beds or fluidized beds. However, it is contemplated that fluidized bed reactors may usually only include a single catalyst such that the catalysts are not substantially mixed, in some embodiments.

Now referring to FIGS. 4 and 5, in embodiments of the described systems and processes, an upgraded oil stream 220 may be used as a feedstock or as a portion of a feedstock for a downstream refinery operation, such as a coking refinery 200 with a hydrocracking process unit as shown in FIG. 4 or a coking refinery 300 with a fluid catalytic cracking (FCC) conversion unit as shown in FIG. 5. In such embodiments, the upgraded oil stream 220 is processed to form one or more refining fractions (such as, for example, gasoline, distillate oil, fuel oil, or coke) by introducing the upgraded oil to the refinery fractionator (such as the atmospheric distillation column 230 in FIGS. 4 and 5) and subsequently subjecting the fractions of the refinery fractionator to a refining processing such as one or more of hydrocracking processing or FCC processing. In the case of upgraded oil stream 220 being used as part of a feedstock, the balance of the feedstock can be crude oil not derived from the pretreatment step described with reference to FIG. 1. A simplified schematic of an example coking refinery is depicted in FIG. 4. While embodiments of downstream refining processing systems are described in this disclosure with reference to FIGS. 4 and 5, it should be understood that these downstream processes are not limiting on the pre-treatment, upgrading process described with reference to FIGS. 1-3. Additionally, it should be understood that while FIGS. 4 and 5 depict representations of some refinery systems, other refinery systems are contemplated, such as any refining system currently utilized to form transportation fuels from crude oil.

FIG. 4 represents a first embodiment of a delayed coking refinery 200 having a coking refinery with a hydrocracking process unit. In FIG. 4, upgraded oil stream 220, which may comprise either pretreatment catalyst reaction effluent stream 109, intermediate liquid product stream 115 or pretreatment final liquid product stream 118 from FIG. 1, enters atmospheric distillation column 230, where it may be separated into at least, but not limited to, three fractions. The three fractions may include a straight run naphtha stream 232, an atmospheric gas oil stream 234, and an atmospheric residue stream 236. In an additional embodiment, virgin crude oil can be added along with upgraded oil stream 220 as a feedstock for the delayed coking refineries 200, 300 of FIGS. 4 and 5.

Atmospheric residue stream 236 may enter vacuum distillation column 240, where the atmospheric residue stream 236 may be separated into a vacuum gas oil stream 242 and a vacuum residue stream 244. In the embodiment shown in FIG. 4, slipstream 246 may be removed from vacuum residue stream 244 and sent to fuel oil collection tank 206. The remainder of vacuum residue stream 244 may enter delayed coking process unit 250, where vacuum residue stream 244 may be processed to create coker naphtha stream 252, coker gas oil stream 254, heavy coker gas oil stream 256, and green coke stream 258, with green coke stream 258 being then sent to coke collection tank 208. Green coke, as used in this disclosure, is another name for a greater quality coke. Coupled with the lower coke yield, a greater liquid yield may be observed resulting in greater amounts of coker gas oil stream 254 and heavy coker gas oil stream 256. Coker gas oil stream 254 in the disclosed systems and methods may be fed to gas oil hydrotreater 270. According to some embodiments, coker gas oil stream 254 may have a relatively large amount of unsaturated content, particularly olefins, which may deactivate downstream HDN catalyst. An increased yield of this stream would normally constrain gas oil hydrotreater 270 catalyst cycle length. However, in embodiments of the disclosed systems and methods, this increased feed to gas oil hydrotreater 270 can be processed due to the improved properties of atmospheric gas oil stream 234 (that is, lesser sulfur and aromatics in the feed).

Still referring to FIG. 4, coker gas oil stream 254 along with atmospheric gas oil stream 234 may be sent to gas oil hydrotreater 270 in order to further remove impurities. According to some embodiments, coker gas oil stream 254 and atmospheric gas oil stream 234 have large amounts of unsaturated content, particularly olefins, which can deactivate downstream HDN catalysts. An increased yield of these streams may normally constrain gas oil hydrotreater 270 catalyst cycle length. However, in accordance with an embodiment of the disclosed systems and methods, the increased feed to gas oil hydrotreater 270 can be processed due to the improved properties of atmospheric gas oil stream 234 and coker gas oil stream 254. Distillate fuel stream 272 exits gas oil hydrotreater 270 is introduced into distillate fuel collection tank 204.

The coker naphtha stream 252, along with the straight run naphtha stream 232, are sent to naphtha hydrotreater 280. Due to the fact that coker naphtha stream 252 and straight run naphtha stream 232 have lesser amounts of sulfur and aromatics than they would normally contain absent the pretreatment steps described with reference to in FIGS. 1-3, naphtha hydrotreater 280 may not have to perform as much hydrodesulfurization as it would normally require, which allows for increased throughputs and ultimately greater yields of gasoline fractions.

Another advantage of an embodiment of the disclosed systems and methods, which further enables the increase in throughput in delayed coking process unit 250, is the fact that atmospheric gas oil stream 234 may have significantly lesser sulfur content.

Vacuum gas oil stream 242 along with heavy coker gas oil stream 256 may be sent to hydrocracker 260 for upgrading to form a hydrocracked naphtha stream 262 and a hydrocracked middle distillate stream 264, with hydrocracked middle distillate stream 264 being fed, along with distillate fuel stream 272, to distillate fuel collection tank 204.

Hydrotreated naphtha stream 282 and hydrocracked naphtha stream 262 are introduced to naphtha reformer 290, where hydrotreated naphtha stream 282 and hydrocracked naphtha stream 262 may be converted from low octane fuels into high-octane liquid products known as gasoline 292. It is believed that naphtha reformer 290 may re-arrange or re-structure the hydrocarbon molecules in the naphtha feedstocks as well as break some of the molecules into lesser molecules. The overall effect may be that the product reformate contains hydrocarbons with more complex molecular shapes having greater octane values than the hydrocarbons in the naphtha feedstocks. In so doing, the naphtha reformer 290 separates hydrogen atoms from the hydrocarbon molecules and produces significant amounts of byproduct hydrogen gas for use as make-up hydrogen feed stream 114 of FIGS. 1-3.

A conventionally operated coking refinery would be limited in throughput by delayed coking process unit 250. The maximum throughput of the refinery would therefore also be limited by the maximum amount of throughput possible through delayed coking process unit 250. However, the disclosed pretreatment systems and methods advantageously enable the processing of an increased amount of heavy oil through the refinery with surprisingly improved results.

If, as in the case of the disclosed systems and methods, an upgraded heavy oil may be processed in the refinery configuration as shown in FIG. 4, the reduction of at least sulfur and aromatics content will cause the performance of the downstream process to be advantageously affected.

In embodiments in which the upgraded heavy oil is combined with untreated crude oil as a feedstock for subsequent refining processes (not shown), for example a delayed coking facility having a delayed coking process unit, the delayed coking process unit can run at essentially the same coke handling capacity it was designed for originally, but with improved yields in all of the liquid products and enhancement of the petroleum coke quality (lower sulfur and metals). One of the positive impacts on delayed coking process unit 250 is that the feed stream will have less metals, carbon and sulfur, since the upgraded crude oil acts like a diluent. The impact of less sulfur will mean that the final coke product will be of a greater grade, resulting in increases of green coke stream 258.

Another refinery embodiment 300, shown in FIG. 5, comprises a coking refinery with an FCC conversion unit, which utilizes the same bottoms conversion but has a different vacuum gas oil conversion. In this embodiment, upgraded oil stream 220 may be fed to this refinery just as in FIG. 4. The embodiments of FIGS. 4 and 5 are similar except FIG. 5 uses a combination of vacuum gas oil hydrotreater 255 and FCC conversion unit 265 in place of a hydrocracker. As was described with reference to the process depicted in FIG. 4, the pretreated processing of upgraded oil stream 220 will impact many or all of the process units within the refinery configuration of FIG. 5. The benefits seen with delayed coking process unit 250 may be analogous to the previous embodiment, such as the increased liquid yield and lower coke production. As discussed previously, this may enable a greater throughput through delayed coking process unit 250, thereby enabling a greater throughput through the refinery. In addition, there may be an increased capacity for further processing coker gas oil stream 254 in gas oil hydrotreater 270, due to the lower sulfur content of coker gas oil stream 254 and its impact on the reduced HDS requirement from gas oil hydrotreater 270.

As depicted in FIG. 5, desulfurized vacuum gas oil stream 257 (from the vacuum gas oil hydrotreater 255) may be introduced to FCC conversion unit 265, where it may be cracked to produce multiple streams. These streams may include a light cycle oil stream 266, FCC gasoline stream 267, and a heavy cycle oil stream 269. Light cycle oil stream 266 may be combined with atmospheric gas oil stream 234 and coker gas oil stream 254 in gas oil hydrotreater 270 to form distillate fuel stream 272. Heavy cycle oil stream 269 may be combined with slipstream 246 at fuel oil collection tank 206. FCC gasoline stream 267 may be joined by gasoline stream 292 at gasoline pool collection tank 202.

Now referring to FIG. 6, a steam cracking and separation system 400 is depicted. The upgraded oil stream 303 (which may comprise any one or more of the catalyst reaction effluent stream 109, intermediate liquid product stream 115, or pretreatment final liquid product stream 118 from the pretreatment systems 100 of FIGS. 1-3) may be passed to a steam cracker unit 348. The steam cracker unit 348 may include a convection zone 350 and a pyrolysis zone 351. The upgraded oil stream 303 may pass into the convection zone 350 along with steam 305. In the convection zone 350, the upgraded oil stream 303 may be pre-heated to a desired temperature, such as from 400° C. to 650° C. The contents of the upgraded oil stream 303 present in the convection zone 350 may then be passed to the pyrolysis zone 351 where it is steam-cracked. The steam-cracked effluent stream 307 may exit the steam cracker unit 348 and be passed through a heat exchanger 308 where process fluid 309, such as water or pyrolysis fuel oil, cools the steam-cracked effluent stream 307 to form the cooled steam-cracked effluent stream 310. The steam-cracked effluent stream 307 and cooled steam-cracked effluent stream 310 may include a mixture of cracked hydrocarbon-based materials which may be separated into one or more petrochemical products included in one or more system product streams. For example, the steam-cracked effluent stream 307 and the cooled steam-cracked effluent stream 310 may include one or more of pyrolysis fuel oil, pyrolysis gasoline, mixed butenes, butadiene, propene, ethylene, methane, and hydrogen, which may further be mixed with water from the stream cracking.

According to one or more embodiments, the pyrolysis zone 351 may operate at a temperature of from 700° C. to 900° C. The pyrolysis zone 351 may operate with a residence time of from 0.05 seconds to 2 seconds. The mass ratio of steam 305 to upgraded oil stream 303 may be from about 0.3:1 to about 2:1.

The cooled steam-cracked effluent stream 310 may be separated by separation unit 311 into system product streams. For example, the separation unit 311 may be a series of separation vessels which separates the contents of the cooled steam-cracked effluent stream 310 into one or more of a fuel oil stream 312, a gasoline stream 313, a mixed butenes stream 314, a butadiene stream 315, a propene stream 316, an ethylene stream 317, a methane stream 318, and a hydrogen stream 319. As used in this disclosure, the system product streams (such as the fuel oil stream 312, the gasoline stream 313, the mixed butenes stream 314, the butadiene stream 315, the propene stream 316, the ethylene stream 317, and the methane stream 318) may be referred to as system products, sometimes used as feeds in downstream chemical processing.

According to additional embodiments, all or a portion of the fuel oil stream 312 may be recycled to the pretreatment system 100 of FIGS. 1-3. The fuel oil stream 312 may be transported to the pretreatment system 100 via fuel oil recycle stream 362. The fuel oil recycle stream may be combined with any stream in the pretreatment system 100 which leads to the hydrotreatment catalyst system 132.

In additional embodiments, gas condensate 364 may be combined with the upgraded oil stream 303, and the upgraded oil and gas condensate enter the steam cracking unit 348. Alternatively, gas condensate may enter the steam cracking unit 348 directly.

The gas condensate may be gas condensate available from the Khuff geological formation. Khuff gas condensate properties, is shown in Table 2.

TABLE 2 Example of Khuff Gas Condensate Property Units Value American Petroleum Institute degrees 52.8 (API) gravity Density grams per cubic centimeter 0.7695 (g/cm³) Sulfur Content weight percent (wt. %) 0.03 Nickel parts per billion by weight Less than 20 (ppbw) Vanadium ppbw Less than 20 Iron ppbw Less than 20 Copper ppbw Less than 20 Sodium Chloride (NaCl) ppbw 50 Content Conradson Carbon wt. % 0.03 Basic nitrogen Parts per million (ppm) Less than 10

Now referring to FIG. 7, in additional embodiments, the feed stream 101, such as crude oil, may be separated into a light feed fraction stream 372 and a heavy feed fraction stream 374. The separation may be conducted in separation unit 376, which may be a flash drum or other suitable separation device. The heavy fraction of the heavy fraction stream 374 and the light fraction of the light fraction stream 372 may be divided by a cut point, where the contents of the heavy fraction generally have a boiling point greater than the cut point and the contents of the light fraction generally have a boiling point less than the cut point. According to one or more embodiments, the cut point of the separation in separation unit 376 may be from 300° C. to 400° C., such as from 325° C. to 375° C., from 340° C. to 360° C., or from 345° C. to 355° C. According to additional embodiments, the cut point of the separation in separation unit 376 may be from 120° C. to 230° C., such as from 150° C. to 210° C., from 160° C. to 200° C., from 170° C. to 190° C., or from 175° C. to 185° C. The heavy fraction stream 374 may be passed to the pretreatment system 100 of any of FIGS. 1-4 where it is hydrotreated via the hydrotreatment catalyst system 132. The light feed fraction stream may be passed directly to the steam cracker unit 348. In such an embodiment, relatively light components of a feed stream may bypass the pretreatment, thus increasing efficiency in the combined system. It is noted that while FIG. 7 depicts the combination of the light feed fraction stream 372 and the upgraded oil stream 303, but also these streams may be separately passed to the steam cracker unit 348.

Referring now to FIG. 8, in one or more embodiments, the upgraded oil (present in separation input stream 410) may be introduced to a separation unit 412 which separates the upgraded oil into one or more transportation fuels. For example, the separation input stream 410 may be separated into one or more of gasoline 414, kerosene 416, or diesel 418. In one embodiment, such as depicted in FIG. 8, a single distillation column separates the contents of the separation input stream 410. In additional embodiments, multiple separation units are utilized for the separation of the separation input stream 410 into three or more streams.

In additional embodiments, other process products are contemplated in addition to, or in combination with, the transportation fuels described herein. For example, some fraction of the separation input stream 410 may be a non-transportation fuel which may be further processed or recycled in the system for further processing.

EXAMPLES

The various embodiments of methods and systems for the upgrading of a heavy fuel will be further clarified by the following examples. The examples are illustrative in nature, and should not be understood to limit the subject matter of the present disclosure.

Example 1 Preparation of Mesoporous Hydrocracking Catalyst

The first hydrocracking catalyst comprising mesoporous zeolite as described previously in this disclosure was synthesized. 74.0 g of commercial NaY zeolite (commercially available as CBV-100 from Zeolyst) was added in 400 milliliters (mL) of 3 molar (M) sodium hydroxide (NaOH) solution and was stirred at 100° C. for 12 hours. Then, 60.0 g of cetyl trimethylammonium bromide (CTAB) was added into prepared mixture while the acidity was controlled at 10 pH with 3 M hydrochloric acid solution. The mixture was aged at 80° C. for 9 hours, and then transferred into a Teflon-lined stainless steel autoclave and crystallized at 100° C. for 24 hours. Following the crystallization, the sample was washed with deionized water, dried at 110° C. for 12 hours, and calcined at 550° C. for 6 hours. The as-made sample was ion-exchanged with 2.5 M ammonium nitrate (NH₄NO₃) solution at 90° C. for 2 hours, followed by a steam treatment (at a flow rate of 1 milliliter per minute (mL/min)) at 500° C. for 1 hour. Then, the sample was ion-exchanged with 2.5 M NH₄NO₃ solution again. Finally, the sample was dried at 100° C. for 12 hours and calcined at 550° C. for 4 hours to form a mesoporous zeolite Y. In a mortar, 34 grams (g) of the mesoporous zeolite Y, 15 g of molybdenum trioxide (MoO₃), 20 g of nickel(II) nitrate hexahydrate (Ni(NO₃)₂.6H₂O), and 30.9 g of alumina (commercially available as PURALOX® HP 14/150 from Sasol) were mixed evenly. Then, 98.6 g of binder made from alumina (commercially available as CATAPAL® from Sasol) and diluted nitric acid (HNO₃) (ignition of loss: 70 wt. %) was added, which pasted the mixture to form a dough by adding an appropriate amount of water. The dough was extruded with an extruder to form a cylindered extrudate. The extrudate was dried at 110° C. overnight and calcinated at 500° C. for 4 hours.

Example 2 Preparation of Conventional Hydrocracking Catalyst

A conventional hydrocracking catalyst (including a microporous zeolite) was produced by a method similar to that of Example 1 which utilized a commercial microporous zeolite. In a mortar, 34 g of microporous zeolite (commercially available as ZEOLYST® CBV-600 from Micrometrics), 15 g of MoO₃, 20 g of Ni(NO₃)₂6H₂O, and 30.9 g of alumina (commercially available as PURALOX® HP 14/150 from Sasol) were mixed evenly. Then, 98.6 g of binder made from boehmite alumina (commercially available as CATAPAL® from Sasol) and diluted nitric acid (HNO₃) (ignition of loss: 70 wt. %) was added, which pasted the mixture to form a dough by adding an appropriate amount of water. The dough was extruded with an extruder to form a cylindered extrudate. The extrudate was dried at 110° C. overnight, and calcinated at 500° C. for 4 hours.

Example 3 Analysis of Prepared Hydrocracking Catalysts

The prepared catalysts of Examples 1 and 2 were analyzed by BET analysis to determine surface area and pore volume. Additionally, micropore (less than 2 nm) and mesopore (greater than 2 nm) surface area and pore volume were determined. The results are shown in Table 3, which shows the catalyst of Example 1 (conventional) had more micropore surface area and micropore pore volume than mesopore surface area and mesopore pore volume. Additionally, the catalyst of Example 2 had more mesopore surface area and mesopore pore volume than micropore surface area and micropore pore volume. These results indicate that the catalyst of Example 1 was microporous (that is, average pore size of less than 2 nm) and the catalyst of Example 2 was mesoporous (that is, average pore size of at least 2 nm).

TABLE 3 Porosity Analysis of Catalysts of Example 1 and Example 2 Catalyst of Example 2 Sample (conventional) Catalyst of Example 1 Surface area (m²/g) 902 895 Micropore (<2 nm) (m²/g) 747 415 Mesopore (>2 nm) (m²/g) 155 480 Mesopore ratio (%) 17.2 53.6 Pore volume, mL/g 0.69 1.05 Micropore (<2 nm), (mL/g) 0.41 0.25 Mesopore (>2 nm). (mL/g) 0.28 0.8 Mesopore ratio (%) 40.6 76.2

Example 4 Preparation of Mesoporous HDN Catalyst

A mesoporous HDN catalyst was prepared by the method described, where the mesoporous HDN catalyst had a measured average pore size of 29.0 nm. First, 50 g of mesoporous alumina was prepared by mixing 68.35 g of boehmite alumina powder (commercially available as CATAPAL® from Sasol) in 1000 mL of water at 80° C. Then, 378 mL of 1 M HNO₃ was added with the molar ratio of H⁺ to Al³⁺ equal to 1.5 and the mixture was kept stirring at 80° C. for 6 hours to obtain a sol. Then, 113.5 g of triblock copolymer (commercially available as PLURONIC® P123 from BASF) was dissolved in the sol at room temperature and then aged for 3 hours, where the molar ratio of the copolymer to Al was equal to 0.04). The mixture was then dried at 110° C. overnight and then calcined at 500° C. for 4 hours to form a mesoporous alumina.

The catalyst was prepared from the mesoporous alumina by mixing 50 g (dry basis) of the mesoporous alumina with 41.7 g (12.5 g of alumina on dry basis) of acid peptized alumina (commercially available as CATAPAL® from Sasol). An appropriate amount of water was added to the mixture to form a dough, and the dough material was extruded to form trilobe extrudates. The extrudates were dried at 110° C. overnight and calcinated at 550° C. for 4 hours. The calcinated extrudates were wet incipient impregnated with 50 mL of aqueous solution containing 94.75 g of ammonium heptanmolybdate, 12.5 g of nickel nitrate, and 3.16 g of phosphoric acid. The impregnated catalyst was dried 110° C. overnight and calcinated at 500° C. for 4 hours.

Example 5 Preparation of Conventional HDN Catalyst

A catalyst was prepared from the conventional alumina by mixing 50 g (dry basis) of the alumina (commercially available as PURALOX® HP 14/150 from Sasol) with 41.7 g (that is, 12.5 g of alumina on dry basis) of acid peptized alumina (commercially available as CATAPAL® from Sasol). Appropriate amount of water was added to the mixture to form a dough, and the dough material was extruded to form trilobe extrudates. The extrudates were dried at 110° C. overnight and calcinated at 550° C. for 4 hours. The calcinated extrudates were wet incipient impregnated with 50 mL of aqueous solution containing 94.75 g of ammonium heptanmolybdate, 12.5 g of nickel nitrate, and 3.16 g of phosphoric acid. The impregnated catalyst was dried 110° C. overnight and calcinated at 500° C. for 4 hours. The conventional HDN catalyst had a measured average pore size of 10.4 nm.

Example 6 Catalytic Performance of Prepared HDN Catalysts

In order to compare the reaction performance of the catalysts of Example 4 and Example 5, both catalysts were tested in a fixed bed reactor. For each run, 80 mL of the selected catalyst was loaded. The feedstock properties, operation conditions, and results are summarized in Table 4. The results showed that the hydrodenitrogenation performance of the catalyst of Example 4 is better than that of the conventional catalyst of Example 5.

TABLE 4 Porosity Analysis of Catalysts of Example 4 and Example 5 Example 5 Catalyst Feed Oil (conventional) Example 4 Conditions Temperature (° C.) 390 390 Pressure (bar) 150 150 Liquid hourly space 0.5 0.5 velocity (LHSV) (hours⁻¹) H₂/oil ratio (L/L) 1200 1200 Product properties Density 0.8607 0.8423 0.8391 C (wt. %) 85.58 86.43 86.51 H (wt %) 12.37 13.45 13.44 S (ppmw) 19810 764 298 N (ppmw) 733 388 169 C5-180° C. (wt. %) 20.19 17.00 17.62 180-350° C. (wt. %) 30.79 36.93 39.00 350-540° C. (wt. %) 30.27 30.65 29.12 >540° C. (wt. %) 18.75 14.32 12.67

Example 7 Catalytic Performance of HDN and Hydrotreating Catalysts

To compare a conventional catalyst system, which includes the catalyst of Example 2 and the catalyst of Example 5 with a catalyst system, which includes the catalyst of Example 1 and the catalyst of Example 4, experiments were performed in a four-bed reactor unit. The four-bed reactor unit included an HDM catalyst, a transition catalyst, an HDN catalyst, and the first hydrocracking catalyst, all in series. The feed and reactor conditions were the same as those reported in Table 4. Table 5 shows the components and volumetric amount of each component in the sample systems. The 300 mL reactor was utilized for the testing.

TABLE 5 Catalyst Bed Loading Sample System 1 Volume (Conventional) Sample System 2 (mL) HDM Commercially available Commercially available 15 Catalyst HDM catalyst HDM catalyst Transition Commercially available Commercially available 15 Catalyst transition catalyst of transition catalyst of HDM and HDS HDM and HDS functions functions HDN Catalyst of Example 5 Catalyst of Example 4 90 Catalyst Hydro- Catalyst of Example 2 Catalyst of Example 1 30 cracking Catalyst

Table 6 reports the catalytic results for Sample System 1 and Sample System 2 of Table 4 with liquid hourly space velocities of 0.2 hour⁻¹ and 0.3 hour⁻¹. The results showed that the catalyst system that included the catalysts of Example 1 and Example 4 (Sample System 2) exhibited a better performance in hydrodenitrogenation, hydrodesulfurization, and conversion of 540° C.+residues.

TABLE 6 Catalyst Performance Results LHSV (hour⁻¹) 0.2 0.3 Catalyst system Sample Sample System 1 System 1 (Con- Sample (Con- Sample ventional) System 2 ventional) System 2 Product properties Density 0.8306 0.771 0.8442 0.8181 S (ppmw) 73 230 301.7 238 N (ppmw) 5 <5 237.3 23 Product yield, wt % FF C1 0.3 0.4 0.4 0.6 C2 0.3 0.6 0.4 0.3 C3 0.4 2.1 0.8 0.5 nC4 0.1 3.8 0.1 0.1 iC4 0.4 2.7 0.5 0.6 <180° C. 18.4 53.3 17.0 24.4 180- 41.4 31.7 37.4 46.1   350° C. 350- 30.5 3.2 30.6 22.0   540° C. >540° C. 8.4 0.0 13.0 3.9 C5+ 98.7 88.1 98.1 96.4

It is noted that one or more of the following claims utilize the term “where” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.”

It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure.

Having described the subject matter of the present disclosure in detail and by reference to specific embodiments, it is noted that the various details described in this disclosure should not be taken to imply that these details relate to elements that are essential components of the various embodiments described in this disclosure, even in cases where a particular element is illustrated in each of the drawings that accompany the present description. Rather, the claims appended hereto should be taken as the sole representation of the breadth of the present disclosure and the corresponding scope of the various embodiments described in this disclosure. Further, it will be apparent that modifications and variations are possible without departing from the scope of the appended claims.

The present disclosure includes one or more non-limiting aspects. A first aspect may include a method for processing heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form an upgraded oil, the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil; and wherein the final boiling point of the upgraded oil is less than or equal to 540° C.; wherein the second hydrocracking catalyst cracks at least a portion of vacuum gas oil in the heavy oil; and wherein the first hydrocracking catalyst comprises a greater average pore size than the second hydrocracking catalyst.

A second aspect includes the first aspect, further comprising passing the upgraded oil to a steam cracker and steam cracking the upgraded oil to form a steam-cracked effluent.

A third aspect includes any of the preceding aspects, wherein the first hydrocracking catalyst comprises a greater pore volume than the second hydrocracking catalyst.

A fourth aspect includes any of the preceding aspects, wherein the first hydrocracking catalyst comprises lesser acidity than the second hydrocracking catalyst.

A fifth aspect includes any of the preceding aspects, wherein the first hydrocracking catalyst comprises a lesser surface area than the second hydrocracking catalyst.

A sixth aspect includes any of the previous aspects, wherein the feed oil is crude oil having an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees.

A seventh aspect includes any of the preceding aspects, further comprising: separating a feed oil into a heavy feed fraction and a light feed fraction; and passing the light feed fraction to the steam cracker; wherein the heavy feed fraction is the heavy oil that is upgraded.

An eighth aspect includes the seventh aspect, wherein the cut point of the light feed fraction relative to the heavy feed fraction is from 300° C. to 400° C.

A ninth aspect includes the seventh aspect, wherein the cut point of the light feed fraction and heavy feed fraction is from 120° C. to 230° C.

A tenth aspect includes any of the preceding aspects, wherein: the hydrodemetalization catalyst, the transition catalyst, and the hydrodenitrogenation catalyst are positioned in series in a plurality of reactors; and the first hydrocracking catalyst, the second hydrocracking catalyst, or both are positioned in one or more reactors downstream of the plurality of reactors.

An eleventh aspect includes the tenth aspect, wherein the one or more reactors downstream of the plurality of reactors is a single packed bed reactor.

A twelfth aspect includes any of the preceding aspects, wherein: the first hydrocracking catalyst comprises a mesoporous zeolite and one or more metals, where the mesoporous zeolite has an average pore size of from 2 nm to 50 nm; or the hydrodenitrogenation catalyst comprises one or more metals on an alumina support, the alumina support having an average pore size of from 2 nm to 50 nm; or both.

A thirteenth aspect includes the second aspects further comprising steam cracking a gas condensate with the upgraded oil.

A fourteenth aspect may include a method for processing heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form an upgraded oil, the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil; and passing the upgraded oil to a steam cracker and steam cracking the upgraded oil to form a steam-cracked effluent stream; wherein the second hydrocracking catalyst cracks at least a portion of vacuum gas oil in the heavy oil; and wherein the first hydrocracking catalyst comprises a greater average pore size than the second hydrocracking catalyst.

A fifteenth aspect includes the fourteenth aspect, further comprising: separating a feed oil into a heavy feed fraction and a light feed fraction; and passing the light feed fraction to the steam cracker; wherein the heavy feed fraction is the heavy oil that is upgraded.

A sixteenth aspect includes any of aspects fourteen or fifteen, wherein: the hydrodemetalization catalyst, the transition catalyst, and the hydrodenitrogenation catalyst are positioned in series in a plurality of reactors; and the first hydrocracking catalyst, the second hydrocracking catalyst, or both are positioned in a one or more reactors downstream of the plurality of reactors.

A seventeenth aspect includes the sixteenth aspect, wherein the one or more reactors downstream of the plurality of reactors is a packed bed reactor.

An eighteenth aspect includes any of aspects fourteen through seventeen, wherein the first hydrocracking catalyst comprises one or more of a greater pore volume, lesser acidity, and a lesser surface area than the second hydrocracking catalyst.

A nineteenth aspect includes any of aspects fourteen through eighteen, wherein: the first hydrocracking catalyst comprises a mesoporous zeolite and one or more metals, where the mesoporous zeolite has an average pore size of from 2 nm to 50 nm; or the hydrodenitrogenation catalyst comprises one or more metals on an alumina support, the alumina support having an average pore size of from 2 nm to 50 nm; or both.

A twentieth aspect includes any of aspects fourteen through nineteen, wherein the feed oil is crude oil having an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees. 

1. A method for processing heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form an upgraded oil, the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil; wherein the final boiling point of the upgraded oil is less than or equal to 540° C.; wherein the second hydrocracking catalyst cracks at least a portion of vacuum gas oil in the heavy oil; and wherein the first hydrocracking catalyst comprises a greater average pore size than the second hydrocracking catalyst.
 2. The method of claim 1, further comprising passing the upgraded oil to a steam cracker and steam cracking the upgraded oil to form a steam-cracked effluent.
 3. The method of claim 1, wherein the first hydrocracking catalyst comprises a greater average pore volume than the second hydrocracking catalyst.
 4. The method of claim 1, wherein the first hydrocracking catalyst comprises a lesser acidity than the second hydrocracking catalyst.
 5. The method of claim 1, wherein the first hydrocracking catalyst comprises a lesser surface area than the second hydrocracking catalyst
 6. The method of claim 1, wherein the feed oil is crude oil having an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees.
 7. The method of claim 2, further comprising: separating a feed oil into a heavy feed fraction and a light feed fraction; and passing the light feed fraction to the steam cracker; wherein the heavy feed fraction is the heavy oil that is upgraded.
 8. The method of claim 7, wherein the cut point of the light feed fraction relative to the heavy feed fraction is from 300° C. to 400° C.
 9. The method of claim 7, wherein the cut point of the light feed fraction and heavy feed fraction is from 120° C. to 230° C.
 10. The method of claim 1, wherein: the hydrodemetalization catalyst, the transition catalyst, and the hydrodenitrogenation catalyst are positioned in series in a plurality of reactors; and the first hydrocracking catalyst, the second hydrocracking catalyst, or both are positioned in one or more reactors downstream of the plurality of reactors.
 11. The method of claim 10, wherein the one or more reactors downstream of the plurality of reactors is a single packed bed reactor.
 12. The method of claim 1, wherein: the first hydrocracking catalyst comprises a mesoporous zeolite and one or more metals, where the mesoporous zeolite has an average pore size of from 2 nm to 50 nm; or the hydrodenitrogenation catalyst comprises one or more metals on an alumina support, the alumina support having an average pore size of from 2 nm to 50 nm; or both.
 13. The method of claim 2, further comprising steam cracking a gas condensate with the upgraded oil.
 14. A method for processing heavy oil, the method comprising: upgrading at least a portion of the heavy oil to form an upgraded oil, the upgrading comprising contacting the heavy oil with a hydrodemetalization catalyst, a transition catalyst, a hydrodenitrogenation catalyst, a first hydrocracking catalyst, and a second hydrocracking catalyst downstream of the first hydrocracking catalyst to remove at least a portion of metals, nitrogen, or aromatics content from the heavy oil and form the upgraded oil; and passing the upgraded oil to a steam cracker and steam cracking the upgraded oil to form a steam-cracked effluent stream; wherein the second hydrocracking catalyst cracks at least a portion of vacuum gas oil in the heavy oil; and wherein first hydrocracking catalyst comprises a greater average pore size than the second hydrocracking catalyst.
 15. The method of claim 14, further comprising: separating a feed oil into a heavy feed fraction and a light feed fraction; and passing the light feed fraction to the steam cracker; wherein the heavy feed fraction is the heavy oil that is upgraded.
 16. The method of claim 14, wherein: the hydrodemetalization catalyst, the transition catalyst, and the hydrodenitrogenation catalyst are positioned in series in a plurality of reactors; and the first hydrocracking catalyst, the second hydrocracking catalyst, or both, are positioned in one or more reactors downstream of the plurality of reactors.
 17. The method of claim 16, wherein the one or more reactors downstream of the plurality of reactors are packed bed reactors.
 18. The method of claim 14, wherein the wherein the first hydrocracking catalyst comprises one or more of a greater pore volume, lesser acidity, and a lesser surface area than the second hydrocracking catalyst.
 19. The method of claim 14, wherein: the first hydrocracking catalyst comprises a mesoporous zeolite and one or more metals, where the mesoporous zeolite has an average pore size of from 2 nm to 50 nm; or the hydrodenitrogenation catalyst comprises one or more metals on an alumina support, the alumina support having an average pore size of from 2 nm to 50 nm; or both.
 20. The method of claim 14, wherein the feed oil is crude oil having an American Petroleum Institute (API) gravity of from 25 degrees to 50 degrees. 